Configurations and methods of flexible CO2 removal

ABSTRACT

A plant includes a pretreatment unit for H2S removal and air dehydration, and at least two absorbers that receive a feed gas at a pressure of at least 300 psig with variable CO2 content (e.g., between 5 to 60 mol %), wherein the feed gas is scrubbed in the absorbers with an ultralean and a semi-lean physical solvent, respectively, at low temperatures to at least partially remove the CO2 from the feed gas. Such configurations produces a low CO2 dry treated gas and a H2S-free CO2 for sequestration while advantageously providing cooling by expansion of the rich solvent that cools the semi-lean solvent and the feed gas, wherein an ultralean solvent is produced by stripping using dry air.

This application claims priority to U.S. provisional application withthe Ser. No. 61/915,173, filed 12 Dec. 2013.

FIELD OF THE INVENTION

The field of the invention is removal of acid gases from a feed gas, andparticularly relates to CO2 removal of variable high CO2 content feedgas.

BACKGROUND OF THE INVENTION

The background description includes information that may be useful inunderstanding the present invention. It is not an admission that any ofthe information provided herein is prior art or relevant to thepresently claimed invention, or that any publication specifically orimplicitly referenced is prior art.

Acid gas removal from various gas streams, especially removal of CO2from natural gas streams has become an increasingly important process asthe sweet gas reservoirs are being depleted and the high CO2 contentfields are being developed. There are relatively large natural gasresources untapped in the world (e.g., Alaska, Continental NorthAmerica, Norway, Southeast Asia, South China Sea, and Gulf of Mexico)that contain very high levels of CO2, often ranging from 15% to 60 mol%. Where CO2 is used for enhanced oil recovery (EOR), CO2 content in thefields is gradually increasing, and further field development must theninclude CO2 removal that can handle variable CO2 content gases.

Typically, gas plants are designed to meet pipeline gas transportationspecifications on inerts, sulfur, hydrocarbons, and water dewpointrequirements and not designed to handle high CO2 content gases (e.g., 50mol % or higher). Such processing facilities include amine treating,glycol dehydration, and hydrocarbon removal for processing low levelsCO2 gases (5 mol % or less). Gas fields with high CO2 content are oftenconsidered uneconomical as technologies for high CO2 removal or variableCO2 removal are considered difficult; and consequently such high CO2 gasfields remained undeveloped. To overcome at least some of thedisadvantages associated with gas production having high CO2 content,numerous CO2 removal processes have been developed which can becategorized into physical and chemical processes, wherein the choice ofthe appropriate gas treatment predominantly depends on the gascomposition, feed gas pressure, product gas specifications and locationof the plants (onshore or offshore).

For example, in one category membrane separators are used to separateacid gases from the natural gas streams using preferential diffusion ofCO2 through membrane elements. A typical membrane system has apre-treatment skid and a series of membrane modules. Membrane systemsare relatively compact and simple to operate and are often used to treatlow volume of high pressure CO2 gases, especially in offshoreapplications. However, membrane elements are prone to fouling andmaterial degradation from gas contaminants and therefore must bemonitored and periodically replaced. While initial capital outlay may belower than with other processes, replacement costs of the membranes addup over the life of the plant. In terms of performance, single stagemembrane separators are relatively non-selective and often produce a CO2waste stream with a high hydrocarbon content, which may not meetenvironmental permits on greenhouse gas. Additional processing equipmentmay be used to improve the membrane performance (e.g., multiple stagesof membrane separators with inter-stage recompression and recycle),however, such equipment will increase the cost and footprint of thesystem, rendering membrane separation economically unattractive.

In another category, a chemical solvent is employed that reacts with theacid gases to form a (typically non-covalent) complex. In processesinvolving a chemical reaction between the acid gas and the solvent, thefeed gases are scrubbed with an alkaline salt solution of a weakinorganic acid (e.g., U.S. Pat. No. 3,563,695 to Benson), or with analkaline solution of organic acids or bases (e.g., U.S. Pat. No.2,177,068 to Hutchinson). All publications identified herein areincorporated by reference to the same extent as if each individualpublication or patent application were specifically and individuallyindicated to be incorporated by reference. Where a definition or use ofa term in an incorporated reference is inconsistent or contrary to thedefinition of that term provided herein, the definition of that termprovided herein applies and the definition of that term in the referencedoes not apply. One particular advantage of a chemical solvent system isthat such systems are quite selective and typically do not absorbhydrocarbons to any significant degrees. Furthermore, the chemicalsolvent systems, such as promoted or activated MDEA, can produce aproduct gas with CO2 content in the low ppm range which is required forLNG production.

However, while use of chemical solvent (e.g. amine) systems may beadvantageous, particularly in treating low CO2 content gases, there areunsurmountable difficulties when applied to treat high CO2 fields. Aminesystems operate by the principle of chemical reaction equilibrium andnot influenced by pressure to any significant extent. Even at high CO2partial pressure, the CO2 rich loading does not changes much. In otherwords, the heat required for amine regeneration is proportional to theamount of CO2 in the feed gases. Thus, as the CO2 content in the fieldincreases, additional amine units must be added to meet sales gasspecification on CO2. Even with activated or promoted tertiary aminesuch as MDEA, the heat requirement for solvent regeneration issignificant for high CO2 content gases, which may consume significantamounts of the treated gas for heating, making such development onceagain uneconomical. Furthermore, the amine processes typically operateat relatively high temperature such that equipment and piping are proneto failure from corrosion and foaming problems. Still further, chemicalsolvent systems typically include columns, heaters, air coolers, pumps,etc., all of which require frequent monitoring and maintenance. Yetanother disadvantage of amine systems is that the treated gas and CO2streams are saturated with water, which must be dried with a drying unitto meet pipeline specifications.

In yet another category, a physical solvent can be used for removal ofhigh CO2 content gases. Unlike amine processes, physical solvent loadingcapacity increases with the acid gas partial pressure according to theprinciple of Henry's law. This principle also favors low absorptiontemperature as low temperature also increases the solvent loading, hencereducing solvent circulation. High partial pressure and low operatingtemperature tends to favor physical solvent operation. For example,methanol processes that operate at cryogenic temperature may be employedas a low-boiling organic physical solvent, as exemplified in U.S. Pat.No. 2,863,527 to Herbert et al. However, cryogenic refrigeration is verycostly, and low temperature solvent also co-absorbs a significant amountof hydrocarbons, resulting in high hydrocarbons losses. Therefore, whilethe methanol process is common in syngas treating, they are rarely usedin natural gas plants.

Alternatively, physical solvent process can be operated at slightlybelow ambient temperature to minimize hydrocarbon losses. For example,the Fluor Solvent Process using propylene carbonate as physical solventcan be employed as taught in U.S. Pat. Nos. 7,192,468; 7,424,808 and7,637,987 to Mak, J. These processes, as shown in Prior Art FIG. 1, arein many cases efficient in removal of high CO2 feed gases and do notrequire heating as solvent regeneration is solely accomplished by flashregeneration. Mak's processes also employ the chilled flashed solvent tocool the absorber removing the CO2 heat of absorption. With suchefficient configurations, refrigeration requirement by the physicalsolvent processes can be nearly or mostly eliminated. Nevertheless,there are limitations on these processes as they require a vacuum flashstage to produce the lean solvent which is energy intensive. Moreover,where vacuum stages are omitted, non-vacuum flash stages will notproduce an ultralean solvent to meet stringent CO2 specifications. Suchprocesses are acceptable as long as the CO2 specification in the productgas is 2 to 3% CO2, but would not meet CO2 content less than 500 ppmv,which may be required in the future to meet regulations on greenhousegas emissions. Low CO2 content treated gas is also advantageous as theproduct can be used for blending with other high CO2 gases.

Therefore, it should be appreciated that most known solvent processeslack an efficient heat exchange integration configuration, and oftenrequire significant refrigeration and/or high solvent circulation, andsometimes require heat for solvent regeneration. In most or almost allof the known physical solvent processes, either heating or the use of avacuum flash system must be applied for solvent regeneration. Even withsignificant fuel and power consumption, these processes cannot fullyregenerate the solvent to an ultralean level that can be used to treathigh CO2 feed gas to meet a low CO2 specification on carbon capture.

Thus, although various configurations and methods are known to removeCO2 from a feed gas, all or almost all of them suffer from one or moredisadvantages. Therefore, there is still a need to provide methods andconfigurations for a flexible and innovative CO2 removal.

SUMMARY OF THE INVENTION

The inventive subject matter provides apparatus, systems, and methods inwhich H2S and CO2 are sequentially (and preferably selectively) removedfrom a hydrocarbonaceous feed gas stream. CO2 is preferably removed froman H2S depleted feed gas using a semi-lean and an ultralean physicalsolvent to form rich and semi-lean solvents that are then regenerated ina process that produces work and refrigeration content. Most preferably,ultralean solvent is formed by dry-air stripping, and a portion of theultralean solvent is combined with the H2S depleted feed gas upstream ofan absorber.

In one aspect of the inventive subject matter, the inventor contemplatesa method of removing acid gases from a hydrocarbonaceous feed gascontaining H2S and CO2 in which H2S is preferentially (and moretypically selectively) removed from the feed gas to so form an H2Sdepleted feed gas. CO2 is then removed from the H2S depleted feed gasusing a first and a second absorber by a semi-lean and an ultraleansolvent, respectively, to so form a product gas (preferably with a CO2content of 500 ppmv to 0.5 mol % CO2), a rich solvent, and the semi-leansolvent. Pressure of the rich solvent is then reduced to generate work,a cooled flashed solvent, a CO2 stream, and refrigeration, and thecooled flashed solvent is employed to cool the H2S depleted feed gas andthe semi-lean solvent. Finally, the flashed solvent is stripped withdried air (preferably at about atmospheric pressure, having a water dewpoint of equal or less than 40° F.) to produce the ultralean solvent,and a portion of the ultralean solvent is combined with the H2S depletedfeed gas, preferably before entry into the first or second absorber.

Most typically, the hydrocarbonaceous feed gas has a pressure of atleast 300 psig and comprises at least 5 (and more typically at least 20)mol % CO2. Where desirable, it is contemplated that the first and asecond absorbers are combined into a single column having a first andsecond absorber section. It is further preferred that the solvent is aphysical solvent, and most preferably propylene carbonate, tributylphosphate, normal methylpyrrolidone, a dimethyl ether of polyethyleneglycol, and/or polyethylene glycol dialkyl ether.

In further contemplated methods, the step of selectively removing H2S isperformed via solvent absorption with an H2S selective solvent oradsorption of H2S to a solid adsorbent. While not limiting to theinventive subject matter, it is also contemplated that the semi-leansolvent is produced from the second absorber and is cooled to atemperature ranging from 20° F. to −20° F., and/or that the rich solventis produced from the first absorber and is flashed to at least twoseparators operating in series. So formed recycle streams are thencompressed and recycled back to the absorber or H2S depleted feed gas.It is further contemplated that the majority (e.g., at least 70%, or atleast 85%) of the CO2 content in the rich solvent is removed from thesolvent at atmospheric pressure, that the first absorber is operated tohave a temperature of about 30° F. to about −10° F. at a bottom section,and/or that the ultralean solvent and the semi-lean solvent have atemperature ranging from 10° F. to −25° F.

Consequently, the inventors also contemplate a plant for acid gasremoval from a hydrocarbonaceous feed gas, typically comprising at least20 mol % CO2. Especially contemplated plants are fluidly coupled to afeed gas source that provides a hydrocarbonaceous feed gas comprisingH2S and CO2 at a pressure of at least 300 psig. An H2S removal unit thenselectively removes H2S from the feed gas to produce an H2S depletedfeed gas, and a first and a second absorber are fluidly coupled inseries to the H2S removal unit and remove CO2 from the H2S depleted feedgas using a semi-lean generated from the second absorber and anultralean solvent generated from the stripping section, respectively,and thereby produce a product gas (preferably having CO2 content of 500ppmv to 0.5 mol % CO2), and a rich solvent. A plurality of pressurereduction stages subsequently receive and reduce pressure of the richsolvent to generate work, a CO2 stream, and a cooled flashed solvent,and first and second heat exchangers use the cooled flashed solvent tocool the H2S depleted feed gas and the semi-lean solvent. Finally, astripping unit strips the flashed solvent with dried air (preferablyhaving a water dew point of equal or less than −40° F.) to produce theultralean solvent, and a conduit is installed to combine a portion ofthe ultralean solvent with the H2S depleted feed gas. As used herein,and unless the context dictates otherwise, the term “coupled to” isintended to include both direct coupling (in which two elements that arecoupled to each other contact each other) and indirect coupling (inwhich at least one additional element is located between the twoelements). Therefore, the terms “coupled to” and “coupled with” are usedsynonymously.

Most preferably, the solvent is a physical solvent (e.g., propylenecarbonate, tributyl phosphate, normal methylpyrrolidone, a dimethylether of polyethylene glycol, and/or polyethylene glycol dialkylethers), and the H2S removal unit removes H2S using a H2S selectivesolvent or a sulfur scavenger adsorbent. In is also contemplated thatthe plurality of pressure reduction stages is configured such that atleast 85% of the CO2 content in the rich solvent is removed from thesolvent at atmospheric pressure.

Various objects, features, aspects and advantages of the inventivesubject matter will become more apparent from the following detaileddescription of preferred embodiments, along with the accompanyingdrawing figures in which like numerals represent like components.

BRIEF DESCRIPTION OF THE DRAWING

Prior Art FIG. 1 is a schematic depicting an exemplary configuration forCO2 removal using a physical solvent in a known process.

FIG. 2 is one exemplary schematic depicting a plant configuration forCO2 removal using two absorber stages according to the inventive subjectmatter.

FIG. 3 is another exemplary schematic depicting a plant configurationfor CO2 removal using one single absorber with two absorption stagesaccording to the inventive subject matter.

DETAILED DESCRIPTION

The inventor has discovered that acid gases, and predominately CO2, canbe removed in a conceptually simple and effective manner to meetstringent CO2 specification of 500 ppmv to 0.5 mol % from a feed gasthat contains H2S and variable CO2 content ranging from 5 mol % to 60mol % CO2 at pressures ranging from 300 psig to 1100 psig, or evenhigher.

In especially preferred methods, H2S is preferentially, and moretypically selectively removed from the feed gas prior to CO2 removalthat is carried out in one or more absorbers. Deep solvent regenerationis achieved in an economic manner by dry air stripping, which will allowthe circulating solvents to remain in a dry state. Such regeneration andsolvent chilling (e.g., to −15° F. to −25° F.) in combination withsequential acid gas removal is particularly effective to maximizesolvent loading and to minimize solvent circulation, and to allow use ofthe same plant to treat varying concentrations of CO2 in the feed gases,while producing a dry CO2 stream can be compressed for reinjection forCO2 sequestration.

Especially preferred H2S removal units will be located upstream of thefirst absorber and uses most preferably an H2S specific process. Thereare various H2S removal methods known in the art, and all of those aregenerally deemed suitable for use. However, especially preferred H2Sremoval units include those that have at least a preference (e.g., atleast more than equal co-absorption at equimolar presence of H2S andCO2), and more typically high selectivity to H2S over CO2. For example,H2S selective H2S removal systems include those based on H2S selectivemembranes, adsorptive processes, alkanolamine processes taking intoconsideration the differential mass transfer resistance, differentialreaction rates with the alkanolamine, and/or chemical/physicalequilibria of H2S and CO2 in solution, etc. Thus, suitable processesinclude the LO-CAT® process (wet scrubbing, liquid redox system thatuses a chelated iron solution, Merichem Company, Houston Tex.), theFLEXSORB® process (sterically hindered amine solvent, Exxon MobilCorporation, Irving Tex.), SULFUROX™, or various molecular sieve orother solid phase bed adsorbents.

With respect to the absorbers in contemplated plants it is generallypreferred that the absorber stage comprises two or more absorbersoperating in series, with the H2S depleted feed gas being fed to thefirst absorber that uses a chilled semi-lean solvent produced by thesecond absorber for CO2 removal. The second absorber uses an ultraleansolvent produced from an air stripper (preferably operating at aboutatmospheric pressure) to remove residual CO2 from overhead vapor fromthe first absorber. It is further preferred that the rich solvent isexpanded, preferably using hydraulic turbines, to produce a chilled richsolvent that can then be used for cooling the feed gas and semi-leansolvent. As will be readily appreciated, the expansion or pressureletdown may occur in several (e.g., at least three) steps, producing atleast one or two recycle streams that are then compressed and fed backto the first absorber or H2S depleted feed gas while the third (orsubsequent) flash step produces a CO2 rich product stream at aboutatmospheric pressure. As used herein, the term “about” in conjunctionwith a numeral refers to a range of +/−10% of that numeral, inclusive.For example, where a system has a pressure of about 1,000 psig, therange refers to pressures between 900-1,100 psig. Thus, and unless thecontext dictates the contrary, all ranges set forth herein should beinterpreted as being inclusive of their endpoints and open-ended rangesshould be interpreted to include only commercially practical values.Similarly, all lists of values should be considered as inclusive ofintermediate values unless the context indicates the contrary.

Most typically, and as further explained in more detail below, a dry airstripper is used for solvent regeneration, and is preferably integratedwith the two stage absorption system using solvent flashing for cooling.In this context, it should be noted that the dry air is used to removeboth, residual water and residual CO2 from the solvent from theatmospheric stage to so produce an ultralean solvent that is then usedin the second absorber. Dry air stripping can advantageously produce anultralean solvent with very low water content (e.g., having water dewpoint of −40° F. and very low CO2 content, typically below 0.1 mol % andmost typically below 0.05 mol %). To optimize absorption, the ultraleansolvent is typically maintained at temperatures between about −15° F. to−30° F., with most, if not all of the refrigeration generated fromexpansion of process streams (preferably rich solvent).

Among other advantages of contemplated configurations, it should berecognized that the processes according to the inventive subject matterare generally non-corrosive due to operation at low temperature andabsence (or very low quantities) of water in the physical solvent. Incontrast, conventional amine units for carbon dioxide removal aregenerally more complex to operate and maintain as such processes tend tobe corrosive and often require antifoam and anti-corrosion injectionsduring operation. Still further, another advantage of contemplatedphysical solvent processes contemplated herein is that, unlike amineprocesses, the solvent circulation rate is less sensitive to increasesin CO2 partial pressure as the CO2 loading in the rich solvent merelyincreases with increasing CO2 concentration in the feed gas. In an amineunit design, the amine circulation rate would need to be increasedlinearly with increasing carbon dioxide content. Moreover, contemplatedphysical solvent processes are generally resistant to freezing(especially compared to known amine treating processes), thus requiringless supporting offsite/utility systems such as steam boilers. Indeed,systems and methods receiving a high CO2 feed gas may not require anycooling duty as the flashing of CO2 from the rich solvent will providethe necessary cooling for regeneration.

For example, a contemplated configuration for an acid gas removal plantis depicted in FIG. 2, where an exemplary plant includes an H2S removalunit 51 and air dehydration unit 52, producing an H2S depleted feed gas4 from hydrocarbonaceous feed gas 1, and a dry air stream 27 from(typically ambient) air, respectively. Preferably, and as already notedabove, the H2S removal unit may include a solid adsorbent (e.g., ironoxide absorbent), a unit for redox processes, sulfur scavenger beds, anamine-based (e.g., MDEA) absorption process, or a sterically hinderedamine adsorption processes. Viewed from another perspective, it isgenerally preferred that the H2S removal unit removes H2S with minimumCO2 co-absorption (i.e., with specificity towards H2S as compared toCO2). It should be particularly noted that a separation of (upstream)H2S removal from (downstream) CO2 removal is counter to ordinarypractice in the art as it is generally deemed advantageous to removeboth acid gases using the same solvent system to so minimize pumping andsolvent regeneration devices and expenses. However, the inventor has nowrecognized that separation of the two removal processes produces aH2S-free CO2 stream that can be used for CO2 sequestration whileminimizing energy consumption of the H2S removal unit by maximizing theCO2 content to the CO2 removal unit, which advantageously utilizes theCO2 content for refrigeration, such that the production of a low CO2product stream can be achieved at lower energy costs. Such energyreduction is at least in part due to the low solvent temperature and airstripping. As will be appreciated, the air drying unit for the airstripper may use cooling by refrigeration, ethylene glycol dehydration,silica gel, or other desiccant bed processes commonly used forinstrument air.

H2S depleted feed gas stream 4 is combined with a slip stream of theultralean solvent 3 (hydrate prevention option), and recycle gas stream5, forming two-phase stream 2 at about 100° F., and the two-phase streamis cooled by product gas stream 8 in exchanger 53 to about 75° F., whichis further cooled by the flashed solvent stream 20 in exchanger 70 toabout 35° F. (or slightly above [e.g., 1-5° F. above] the gashydrocarbon dew-point temperature). The chilled gas stream 7 enters thefirst absorber 69. It should be particularly appreciated that the use ofultralean solvent mixing with the treated gas depresses the waterdewpoint of the treated gas, allowing cooling the feed gas to be cooledto a relatively low temperature while avoiding hydrate formation thatmay cause equipment blockage.

With respect to the CO2 content in the feed gas, it is contemplated thatthe systems and methods presented herein are generally suitable for awide range of CO2 content while producing a product gas with lowresidual acid gas content (e.g., at or below 0.5 mol %, or at or below500 ppmv). Therefore, the solvent unit in most typical systems andmethods can be used to treat a hydrocarbonaceous feed gas having avariable CO2 content of between about 5 mol % to about 60 mol % CO2.Therefore, contemplated systems methods can be used in gas processingplants that are required to treat variable CO2 content gases withoutfurther modification to accommodate changes in CO2 content. Furthermore,it should be recognized that the pressure of contemplated feed gases mayvary considerably, but will in some cases be at least 300 psig, in othercases at least 600 psig, in further cases typically at least 1200 psig,and in still other cases at least 1500 psig. Moreover, while it isgenerally contemplated that at least a portion of the feed gas pressureis due to the pressure of the gas contained in a well, it should also berecognized that where appropriate, the pressure may be increased usingone or more compressors.

Consequently, and with respect to suitable feed gases it is contemplatedthat various natural and synthetic feed gases are appropriate. However,particularly preferred feed gases include natural gas, and especiallynatural gas with CO2 content that is at least about 5 mol %, moretypically 10 mol %, even more typically 20 mol %, and most typically 40mol % or even higher. Therefore, especially suitable feed streamsinclude natural gas feed streams from oil and gas fields from Alaska,Norway, Southeast Asia, South China Sea and Gulf of Mexico.

It is further preferred that the first absorber uses semi-lean solvent10 from the second absorber 54 that is pumped by pump 54P forming stream11, which is cooled with the chilled flashed solvent 21 in exchanger 55to about 10° F. to −20° F. forming stream 12. Stream 12 may further bechilled (optional) using refrigeration chiller 56 forming stream 13 atabout 10° F. to −25° F. before being fed to the first absorber. Itshould be appreciated that high CO2 feed gases (e.g., 30 mol % to 60 mol%) do not require external refrigeration as chilling from CO2 flashingwill provide sufficient cooling. In contrast, with low CO2 feed gas (5mol %) the amount of CO2 flashing is reduced and typically notsufficient to cool the absorber, which then necessitates externalrefrigeration.

With respect to solvents employed in contemplated absorbers,particularly preferred solvents include propylene carbonate (or othersolvent with similar properties) that allows the processes to operate at−20° F. or lower with low operating costs and capital costs. With suchor similar solvent, the process can achieve low solvent circulation, lowmethane absorption, low energy consumption, and requires no watermakeup, while allowing plant construction using carbon steel material.Thus, in most aspects of the inventive subject matter, suitable solventsare non-aqueous solvents that will comprise minimal to no water (e.g.,equal or less than 1 wt %, preferably equal or less than 0.5 wt %, morepreferably equal or less than 0.11 wt %), such that a dry CO2 gas can beproduced suitable for CO2 sequestration. However, there are numerousphysical solvents known in the art that may also be applicable andexemplary preferred physical solvents include tributyl phosphate, normalmethylpyrrolidone, dimethyl ether of polyethylene glycol, and/or variouspolyethylene glycol dialkyl ethers. Alternatively, other solventsincluding enhanced tertiary amine (e.g., piperazine) or other solventmay be employed having similar behavior as physical solvent.Contemplated methods and configurations use a physical solvent(preferably propylene carbonate) which can be regenerated withoutheating process (without fuel gas consumption) and which can produce alow CO2 content product gas (500 ppmv).

The first absorber 69 produces an overhead vapor stream 71 withpartially removed CO2 and a rich solvent bottom stream 9, having atemperature of about 10° F. to 40° F. The overhead vapor is routed tothe bottom of the second absorber 54 that uses ultralean solvent stream29 at about −20° F. to produce a product gas stream 8 containing 500 ppmto 0.5 mol % CO2. It should be recognized that physical solventperformance improves with low operating temperatures. In this example,it should be noted that the low limit of about −20° F. is selectedbecause of the favorable physical property characteristics (especiallylow surface tension and low viscosity) for heat and mass transfer inexchangers and separation equipment.

It is especially preferred that the cooling duty in the exchanger 55 issupplied by the solvent stream 21 which is chilled from work extractedin hydraulic turbines 57 and 59 and the heat of CO2 desorption inseparator 58 and 60. However, it should be recognized that cooling mayalso be provided by other streams, produced internally or externallywithin the plant, such as using the JT valve 61, and/or the use ofpropane refrigeration. It should also be appreciated that the pressureof the letdown stream to JT valve 61 is optimally controlled to avoidover-cooling of the solvent. In general, it is preferred that thetemperature of stream 20 be maintained at an acceptably low temperatureas high solvent viscosity and surface tension due to low temperaturescan adversely impact the performance of heat and mass transfer in heatexchangers and contactors.

The rich solvent stream 9 from the first absorber is letdown in pressurein hydraulic turbine 57, reducing pressure to typically about ⅓ to ½ ofthe feed gas pressure, which cools the rich solvent to about 15° F. Itis generally contemplated that the hydraulic turbine is an energyefficient device as it produces shaft work to operate the circulationpump while at the same time generating refrigeration. It should beappreciated that shaft work and cooling increases with CO2 content inthe feed gas, and with sufficiently high CO2 content (60%), thehydraulic turbines can support the power consumption of the circulationpump as well as the refrigeration requirement. Such solventconfiguration is an extremely energy efficient process.

The two phase stream 15 is flashed to separator 58, which produces afirst flashed vapor stream 16 containing methane and CO2 and iscompressed by recycle gas compressor 67. The compressed gas stream 30 iscooled by ambient air in exchanger 68 to about 100° F. forming stream 5that is recycled back to the absorber section. The flashed liquid stream17 is expanded in a second hydraulic turbine 59 to a pressure reduced byat least half to form an expanded rich solvent stream 18, at about −10°F., which is further separated in separator 60 producing vapor stream 19and liquid stream 27. The flash vapor stream 19 is compressed togetherwith stream 16 and recycled back to the absorber section. It should beappreciated that high methane recovery (e.g., 99% or higher) can beachieved by further lowering the pressure in separator 60. However, highmethane recovery must be justified against the expenses of higher powerconsumption by the recycle gas compressor, which should be evaluated ona case by case basis.

Liquid stream 27 from the second separator is further letdown inpressure using JT valve 61, which lowers the solvent temperature suchthat it can be used to cool feed gas in exchanger 70 and semi-leansolvent in exchanger 55. The CO2 rich solvent from exchanger 55 isheated to about 10 to −15° F. to form stream 22 that is flashed to theseparator 62 at about atmospheric pressure, producing CO2 rich stream 23and a flashed liquid stream 24. The CO2 stream 23 contains over 95% CO2which can be further compressed for reinjection and enhanced oilrecovery for CO2 sequestration, or further purified to produce a CO2product for chemical manufacturing or food grade CO2.

The flashed solvent stream 24 is routed via valve 63 as stream 25 tostripper 64 using dry air 27 as the stripping medium. Dry air strippingis energy efficient as it can maintain a water balance of the unit byremoving almost all the water content in the lean solvent as well asresidual CO2, producing a dry and ultralean solvent 28 that can be usedto dry and treat the feed gas to meet very low CO2 specification (500ppmv). It should also be noted that the air stripping operation alsolowers the solvent temperature as residual CO2, hydrocarbons and waterare flashed off producing more refrigeration. The ultralean solvent ispumped by pump 65 forming stream 29, a portion of which is returned tothe second absorber 54. The air stripper overhead stream 26 containsresidual CO2, water, and minimal hydrocarbons that can be sent toincineration unit 66 or waste heat recovery. It should be noted that thehydrocarbon content in stream 26 provides heating values that isrequired for the incineration process.

It should also be appreciated that dry air stripping will become afeasible option in most circumstances only by removal of H2S from thehydrocarbonaceous feed gas prior to removal of CO2. Heretofore knownprocesses without upstream H2S removal cannot use air for solventregeneration under all or almost all circumstances as air would reactwith H2S in the rich solvent, resulting in sulfur deposition and variousequipment plugging problems. Moreover, dry stripping also allowsreduction of the residual water content in the regenerated solvent,which in turn enables very low temperature operation (e.g., less than−10° F., more typically less than −15° F., most typically less than −20°F.) of the solvent, thereby reducing solvent circulation rate andincreasing energy and absorption efficiency.

FIG. 3 exemplarily depicts another schematic plant configuration for CO2removal in which the two absorber vessels are integrated into a singleabsorber tower to so preserve plot space. Here, the individual absorbervessels are configured as absorber sections operating substantially atthe same pressure, and are separated from each other via a chimney trayor other suitable element that permits upwards gas flow while preventingdirect flow of liquid from the upper section to the lower section. Withrespect to the components in FIG. 3 as compared to those in FIG. 2, itshould be noted that the same numerals indicate the same components, andthat all considerations for the components of FIG. 2 also apply to thecorresponding components in FIG. 3.

An exemplary overall mass balance for contemplated methods andconfiguration for a high CO2 content feed gas (here: 55.6 mol %) at apressure of about 1100 psig is shown in Table 1. The product gas is adry gas that meets pipeline gas specification with maximum CO2 contentof 0.5 mol %. For more stringent CO2 specifications, the CO2 content canbe further reduced to about 500 ppmv with additional air stripping andcirculation.

TABLE 1 Stream Feed Dry Feed Treated Gas CO2 Dry Air Vent Mole FractionN2 0.071 0.071 0.161 0.000 0.790 0.412 O2 — — 0.000 — 0.210 0.109 CO20.556 0.557 0.005 0.991 — 0.475 H2S 4 ppm — — — — — CH4 0.362 0.3630.819 0.003 — 0.000 C2H6 0.006 0.006 0.012 0.001 — 0.000 C3H8 0.0020.002 0.002 0.002 — 0.000 IC4 0.000 0.000 0.000 0.000 — 0.000 NC4 0.0010.001 0.000 0.001 — 0.001 IC5 — — — — — — NC5 0.000 0.000 0.000 0.000 —0.000 C6+ 0.001 0.001 0.000 0.001 — 0.001 H2O 0.001 0.000 0.000 0.000 —0.003 Temperature, 104.0 104.0 82.0 −8.9 100.0 −14.5 Pressure, psig1,102.3 1,099.3 1,075.0 5.0 5.0 1.0 Flow, MMscfd 101 101 44 52 5 9

An exemplary overall mass balance for contemplated methods andconfiguration for a intermediate CO2 content feed gas (here: 32 mol %)at a pressure of about 1100 psig is shown in Table 2. The product gas isa dry gas that meets pipeline gas specification with maximum CO2 contentof 0.5 mol %. Once more, for more stringent CO2 specifications, CO2content can be further reduced to about 500 ppmv with additional airstripping and circulation.

TABLE 2 Stream Feed Dry Feed Treated Gas CO2 Dry Air Vent Mole FractionN2 0.077 0.077 0.114 0.000 0.790 0.361 O2 — — 0.000 — 0.210 0.096 CO20.319 0.319 0.005 0.979 — 0.533 H2S 4 ppm — — — — — CH4 0.585 0.5860.862 0.005 — 0.000 C2H6 0.011 0.011 0.015 0.003 — 0.000 C3H8 0.0030.003 0.003 0.003 — 0.001 IC4 0.001 0.001 0.000 0.001 — 0.001 NC4 0.0010.001 0.000 0.001 — 0.001 IC5 0.000 0.000 0.000 0.001 — 0.001 NC5 0.0000.000 0.000 0.000 — 0.000 C6+ 0.003 0.003 0.001 0.005 — 0.006 H2O 0.0010.000 0.000 0.000 — 0.003 Temperature, ° F. 104.0 104.0 82.0 −13.1 100.0−18.6 Pressure, psig 1,102.3 1,099.3 1,075.0 5.0 5.0 1.0 Flow, MMscfd101 101 69 28 4 8

An exemplary overall mass balance for contemplated methods andconfiguration for a intermediate CO2 content feed gas (here: 5.7 mol %)at a pressure of about 565 psig is shown in Table 3. The product gas isa dry gas that meets pipeline gas specification with maximum CO2 contentof 0.5 mol %. As already noted before and where desired, for morestringent CO2 specifications, CO2 content can be further reduced toabout 500 ppmv with additional air stripping and circulation.

TABLE 3 Treated Stream Feed Dry Feed Gas CO2 Dry Air Vent Mole FractionN2 0.076 0.077 0.081 0.000 0.790 0.537 O2 — — 0.000 — 0.210 0.143 CO20.057 0.058 0.005 0.769 — 0.278 H2S — — — — — — CH4 0.820 0.822 0.8760.070 — 0.001 C2H6 0.027 0.027 0.027 0.054 — 0.003 C3H8 0.010 0.0100.009 0.058 — 0.010 IC4 0.002 0.002 0.001 0.018 — 0.006 NC4 0.002 0.0020.001 0.018 — 0.009 IC5 0.001 0.001 0.000 0.006 — 0.005 NC5 0.000 0.0010.000 0.003 — 0.003 C6+ 0.001 0.001 0.000 0.004 — 0.004 H2O 0.001 0.0000.000 0.000 — 0.003 Temperature, 78.8 78.8 68.0 −14.9 100.0 −21.2 ° F.Pressure, 565.5 562.5 548.0 5.0 5.0 1.0 psia Flow, 101.0 100.8 95.6 1.97.3 10.7 MMscfd

It should be appreciated that selective removal of H2S upstream of CO2removal is particularly beneficial as it maximizes the CO2 to thesolvent unit, avoids the common problems of sulfur deposition in thestripper when air is used for stripping, and produces a sulfur free CO2for sequestration. It should also be appreciated that dry air strippinghas several additional advantages. First, dry air is readily availableand inexpensive. Second air stripping can produce an ultralean solventfor treating to meet a very low CO2 specification (500 ppmv or evenlower) in the product gas. Third, dry air stripping removes the moisturecontent in the lean solvent, allowing the unit to operate at a lowtemperature. Forth, air stripping will lower the solvent temperature asthe residual CO2 content and hydrocarbons are desorbed. The ultraleansolvent increases the CO2 pickup in the absorber while the low solventtemperature reduces the absorber temperature, both of which effectivelyreduce the solvent circulation. There, it should be noted thatperformance of the methods and configuration is superior to heretoforeknown configurations and methods that all use vacuum flash forregeneration.

Moreover, it should also be appreciated that the thusly flashed CO2product stream is a dry stream and contains over 95 mol % CO2, which issulfur free suitable for enhanced oil recovery without further need ofprocessing. If necessary or desired, higher purity CO2 and/or highermethane recovery (99.5% or higher) can be achieved by increasing thetemperatures and/or reducing the pressures of the flash separators andincreasing the recycle flow rates.

It should be apparent to those skilled in the art that many moremodifications besides those already described are possible withoutdeparting from the inventive concepts herein. The inventive subjectmatter, therefore, is not to be restricted except in the spirit of theappended claims. Moreover, in interpreting both the specification andthe claims, all terms should be interpreted in the broadest possiblemanner consistent with the context. In particular, the terms “comprises”and “comprising” should be interpreted as referring to elements,components, or steps in a non-exclusive manner, indicating that thereferenced elements, components, or steps may be present, or utilized,or combined with other elements, components, or steps that are notexpressly referenced. Where the specification or claims refer to atleast one of something selected from the group consisting of A, B, C . .. and N, the text should be interpreted as requiring only one elementfrom the group, not A plus N, or B plus N, etc. Moreover, and as used inthe description herein and throughout the claims that follow, themeaning of “a,” “an,” and “the” includes plural reference unless thecontext clearly dictates otherwise. Also, as used in the descriptionherein, the meaning of “in” includes “in” and “on” unless the contextclearly dictates otherwise.

What is claimed is:
 1. A method of treating a hydrocarbonaceous feed gasthat contains H2S and CO2, the method comprising the steps of:selectively removing H2S from the feed gas to produce an H2S depletedfeed gas; using a first absorber and a second absorber to remove CO2from the H2S depleted feed gas using a semi-lean and an ultraleansolvent, respectively, thereby producing a product gas and a richsolvent; reducing pressure of the rich solvent to generate work, acooled flashed solvent, a CO2 stream, and refrigeration; using thecooled flashed solvent to cool the H2S depleted feed gas and thesemi-lean solvent; stripping the cooled flashed solvent with dried airto thereby produce the ultralean solvent; and combining a portion of theultralean solvent with the H2S depleted feed gas upstream of the firstabsorber and the second absorber and upstream of the using the cooledflashed solvent to cool the H2S depleted feed gas.
 2. The method ofclaim 1 wherein the hydrocarbonaceous feed gas has a pressure of atleast 300 psig and comprises at least 5 mol % CO2.
 3. The method ofclaim 1 wherein the first and second absorbers are configured into asingle column having a first and second absorber section.
 4. The methodof claim 1 wherein the solvent is a physical solvent selected from thegroup consisting of propylene carbonate, tributyl phosphate, normalmethyl pyrrolidone, a dimethyl ether of polyethylene glycol, and apolyethylene glycol dialkyl ether.
 5. The method of claim 1 wherein thestep of selectively removing H2S comprises a step of solvent absorptionwith an H2S selective solvent or a step of adsorption of H2S to a solidadsorbent.
 6. The method of claim 1 wherein the product gas has a CO2content of 500 ppmv to 0.5 mol % CO2.
 7. The method of claim 1 whereinthe dried air has a water dew point of equal or less than −40° F.
 8. Themethod of claim 1 wherein the semi-lean solvent is produced from thesecond absorber and cooled to a temperature between 10° F. to −20° F. 9.The method of claim 1 wherein the rich solvent is flashed to twoseparators operating in series, and wherein at least one or two recyclestreams are produced by the separators that are then compressed andrecycled back to the first absorber, the second absorber, or the H2Sdepleted feed gas.
 10. The method of claim 1 wherein at least 85% of theCO2 content in the rich solvent is removed from the solvent atatmospheric pressure.
 11. The method of claim 1 wherein the step ofstriping the flashed solvent with dried air is performed at aboutatmospheric pressure.
 12. The method of claim 1 wherein the firstabsorber is operated to have a temperature of about 30° F. to about −10°F. at a bottom section.
 13. The method of claim 1, wherein the ultraleansolvent and the semi-lean solvent have a temperature ranging from −25°F. to 105° F.
 14. A method of treating a hydrocarbonaceous feed gas thatcontains H₂S and CO₂, the method comprising the steps of: removing H₂Sfrom the feed gas to produce an H₂S depleted feed gas; combining a firstportion of an ultralean solvent with the H₂S depleted feed gas; coolingthe H₂S depleted feed gas having the first portion of the ultraleansolvent using a cooled flashed solvent to produce a cooled H₂S depletedfeed gas; using a first absorber and a second absorber to remove CO₂from the cooled H₂S depleted feed gas using a semi-lean solvent and asecond portion of the ultralean solvent, respectively, thereby producinga product gas and a rich solvent; reducing a pressure of the richsolvent to generate work, the cooled flashed solvent, a CO₂ stream, andrefrigeration; and stripping the cooled flashed solvent with dried airto thereby produce the ultralean solvent.
 15. The method of claim 14wherein the first and second absorbers are configured into a singlecolumn having a first and second absorber section.
 16. The method ofclaim 14 wherein the solvent is a physical solvent selected from thegroup consisting of propylene carbonate, tributyl phosphate, normalmethyl pyrrolidone, a dimethyl ether of polyethylene glycol, and apolyethylene glycol diallyl ether.
 17. The method of claim 14 whereinthe dried air has a water dew point of equal or less than −40° F. 18.The method of claim 14 wherein the rich solvent is flashed to twoseparators operating in series, and wherein at least one or two recyclestreams are produced by the separators that are then compressed andrecycled back to the first absorber, the second absorber, or the H2Sdepleted feed gas.
 19. The method of claim 14 wherein at least 85% ofthe CO₂ content in the rich solvent is removed from the solvent atatmospheric pressure.
 20. The method of claim 14 wherein the step ofstripping the flashed solvent with dried air is performed at aboutatmospheric pressure.